Patent Application
20180201845
This application is directed to processes for reducing acids in high acid hydrocarbon feed oils using metal-naphthenate precipitation.
Corrosion is a critical issue when refineries process crude oils having high total acid number (TAN). Processing high TAN crudes can result in high equipment maintenance costs, expensive metallurgy, and refinery outages when equipment failures occur. Improved processes and equipment are needed for reducing acids in high acid hydrocarbon feed oils, including high TAN crudes. Naphthenic acids are present in crude oil. Fractions that are rich in naphthenic acids can cause corrosion damage to oil refinery equipment; the phenomenon of naphthenic acid corrosion (NAC) has therefore been well researched. Crude oils with a high content of naphthenic acids are often referred to as high TAN crude oils or high acid crude (HAC) oil.
Crude oils having high TAN are often sold at a discount, making them less valuable to crude oil producers.
Processes and equipment for acid removal in high TAN hydrocarbon feed oils have included caustic washing, adsorption, hydro-treating, and acid extraction, but with various disadvantages. For high acid crude production, naphthenate precipitation has been a known risk. In the last decade, many researchers have investigated how to mitigate the risk associated with naphthenate precipitation. The potential equilibria and reactions involving naphthenic acids in systems comprising both hydrocarbon oils and water are very complex.
This application provides a process for reducing a TAN of a hydrocarbon feed oil, comprising:
a. combining an alkaline earth metal, in an aqueous solution having a pH of 10 to 14, with the hydrocarbon feed oil having an initial TAN from 0.5 to 150 mg KOH/g to make a mixture;
b. vigorously mixing the mixture;
c. precipitating a metal-naphthenate salt in the mixture; and
d. removing the metal-naphthenate salt to reduce the initial TAN by 50 to 100% in a treated feed oil;
wherein a weight ratio of the hydrocarbon feed oil to the aqueous solution in the mixture is from 0.25:1 to 20:1
This application also provides a process for reducing a TAN of a hydrocarbon feed oil, comprising:
a. combining an inorganic alkaline earth metal salt having a water solubility at 20° C. from 35 to 150 g/100 g water, in an aqueous solution having a pH of 10 to 14, with the hydrocarbon feed oil having an initial TAN from 0.5 to 150 mg/g KOH to make a mixture;
b. precipitating a metal-naphthenate salt in the mixture;
c. collecting the metal-naphthenate salt at an interface between an upper oil phase and a lower aqueous phase; and
d. removing the metal-naphthenate salt to reduce the initial TAN by 50 to 100% in a treated feed oil.
The present invention may suitably comprise, consist of, or consist essentially of, the elements in the claims, as described herein.
This application discloses new processes to remove acids, such as naphthenic acid, from hydrocarbon feed oils through precipitation of naphthenate.
Examples of hydrocarbon feed oils having high initial TAN include a wide variety of different hydrocarbon feeds. In one embodiment, the hydrocarbon feed oil is selected from the group consisting of a mineral crude oil, a synthetic crude oil, a distillate product, a straight-run feed, an atmospheric distillation bottom, a vacuum distillation bottom, a vacuum gas oil, a biologically-derived oil, and mixtures thereof.
This invention intentionally utilizes the property of metal-naphthenate formation to remove naphthenic acids from a hydrocarbon feed oil stream by precipitation:
For example, as follows:
Ca+++2 RCOO−→Ca(RCOO)2, where R represents a hydrocarbon chain in the naphthenic acid group.
By carefully selecting process conditions such as a pH value of the aqueous solution, properties and concentrations of alkaline earth metal ions, process pressure and temperature, naphthenic acids in hydrocarbon feed oil streams can be removed by metal-naphthenate precipitation. Alkaline earth metals such as calcium, barium, or magnesium, can be introduced to the aqueous solution, and the pH value of the aqueous solution can be carefully controlled to induce metal-naphthenate precipitation.
In one embodiment, the metal-naphthenate is calcium naphthenate. Calcium naphthenate is neither soluble in water nor the hydrocarbon feed oil. Having a density higher than the hydrocarbon feed oil but lower than water, the calcium naphthenate accumulates at the oil/water interface which can be removed from the process unit to produce a treated feed oil with the reduced TAN.
If a highly stable oil-water emulsion is formed in the mixture from the mixer, a demulsifier additive can be either introduced to the separator or otherwise added to the mixture to help break the emulsion.
Some examples of demulsifiers that could be used can be based on one or more of the following chemistries: acid catalyzed phenol-formaldehyde resins, base catalyzed phenol-formaldehyde resins, epoxy resins, polyethylene-imines, polyamines, di-epoxides, polyols, and dendrimers. The above demulsifying chemicals can sometimes be ethoxylated (and/or propoxylated) to provide the desired degree of water/oil solubility. The addition of ethylene oxide increases water solubility, and propylene oxide decreases it. Commercially available demulsifier formulations can be a mixture of two to four different chemistries, in carrier solvent(s) such as xylene, heavy aromatic naphtha, isopropanol, methanol, 2-ethylhexanol, or diesel.
The alkaline earth metal is in an aqueous solution having a pH of 10 to 14. In one embodiment, the alkaline earth metal is a calcium, a barium, a magnesium, or a mixture thereof. In the aqueous solution, the alkaline earth metal provides alkaline earth metal cations, such as Ca2+, Mg2+, or Ba2+. The alkaline earth metal, including the alkaline earth metal cations, are combined with the hydrocarbon feed oil having an initial TAN from 0.5 to 150 mg/g KOH to make the mixture. These alkaline earth metal ions can be provided to the aqueous solution by adding an inorganic alkaline earth metal salt such as, for example, calcium chloride (CaCl2), calcium nitrate, calcium nitrite, calcium iodide, calcium bromide, magnesium chloride, magnesium bromide, barium chloride, barium bromide, or mixtures thereof. The pH of the aqueous solution can be adjusted by adding a base or a basic solution in water, using bases such as NaOH, KOH, NH4OH, or mixtures thereof.
In one embodiment, the inorganic alkaline earth metal salt has a high water solubility, such as a water solubility at 20° C. from 35 to 150 g/100 g water. Examples of inorganic alkaline earth metal salts within this range of water solubility (g/100 g water) include: barium chloride (35.8), magnesium chloride (54.6), calcium iodide (66), calcium chloride (74.5), calcium nitrite (84.5), magnesium bromide (101), barium bromide (104), calcium nitrate (121.2), and calcium bromide (143). In one embodiment, the inorganic alkaline earth metal salt is present in an amount such that the solution comprises greater than 0.05 wt % of the inorganic alkaline earth metal salt, such as from 0.1 to 10 wt %.
In one embodiment, the alkaline earth metal is introduced in the aqueous solution by using alkaline earth metal hydroxides. In one embodiment, the alkaline earth metal ions such as Ca2+, Mg2+, or Ba2+ can also be additionally provided to the aqueous solution by adding alkaline earth metal hydroxides, such as Ca(OH)2, Mg(OH)2, Ba(OH)2, or a mixture thereof to the aqueous solution. Similar to when using the inorganic alkaline earth metal salts described earlier, the pH of the aqueous solution can be adjusted by adding a basic solution such as NaOH, KOH, NH4OH, or a mixture thereof.
In one embodiment, the process can additionally comprise adding a base to the aqueous solution to maintain a contacting pH of the mixture above 9.0. Examples of bases that could be added include NaOH, KOH, NH4OH, and mixtures thereof.
In one embodiment, an advantage of either using alkaline earth metal hydroxides, or additionally using alkaline earth metal hydroxides along with the inorganic alkaline earth metal salt is that they can reduce the possibility of contamination of anions from the inorganic alkaline earth metal salt in the treated feed oil. For example, the alkaline earth metal salt CaCl2 is effective to precipitate naphthenic acid from hydrocarbon feed, as shown in Examples 2 and 3 below, however, potential Cl− contamination to the hydrocarbon feed could be a safety concern since residual Cl− in treated feed oil could be very corrosive. However, hydroxides of alkaline earth metals tend to have lower solubility in water, especially at high temperatures. As a result, the maximum concentration of the alkaline earth metal cation in the aqueous solution will be limited by its solubility, and a higher aqueous to oil ratio may have to be used to provide sufficient alkaline earth metal cations to precipitate the naphthenic acid in the hydrocarbon feed. A higher aqueous phase volume will require a larger reaction volume, which in turn could lead to higher capital expenditure (CAPEX) for the treatment unit.
In one embodiment, an optimum balance can be achieved by introducing both an inorganic alkaline earth metal salt and an alkaline earth metal hydroxide to the aqueous solution to achieve an acceptable level of any anion contaminant (e.g., from the inorganic alkaline earth metal salt) in the treated feed oil and to provide a commercially acceptable volume of a process unit used to perform the process.
The process comprises combining the alkaline earth metal, in the aqueous solution having the pH of 10 to 14, with the hydrocarbon feed oil having an initial TAN from 0.5 to 150 mg/g KOH to make a mixture. The combining can be done by introducing the aqueous solution to the hydrocarbon feed, by introducing the hydrocarbon feed to the aqueous solution, or by simultaneously introducing them together to make the mixture. The amount of the alkaline earth metal that is introduced to the hydrocarbon feed oil is selected to provide a suitable amount to form an alkaline earth metal salt of the naphthenic acid, i.e., to form a metal-naphthenate. In one embodiment, the amount of the alkaline earth metal that is introduced provides a mole ratio of the alkaline earth metal to a naphthenic acid content in the mixture that is 0.5:1 or higher, such as from 0.5:1 to 5.0:1.
In one embodiment, the weight ratio of the hydrocarbon feed oil to the aqueous solution in the mixture is greater than or equal to 0.25:1, such as from 0.25:1 to 20:1. In one embodiment the weight ratio of the hydrocarbon feed oil to the aqueous solution in the mixture is from 0.35:1 to 10:1.
In one embodiment, the combining and precipitating occur at a temperature less than 200° C., such as from 10° C. to 150° C. In one embodiment the combining and precipitating can occur at room temperature (20 to 25° C.). For example, in one embodiment, the process can be performed in a desalter in a refinery. The temperatures in the desalter can be greater than 100° C., such as from about 120° C. to about 150° C.
In one embodiment, the combining and precipitating occur at a pressure greater than 0 kPa, such as from 10 to 2,000 kPa. For example, when the process is performed in a desalter in a refinery, the pressures in the desalter can be greater than 300 kPa, such as from about 350 kPa to about 1700 kPa. Upstream from the desalter, the hydrocarbon feed oil (e.g., mineral crude oil) can be mixed with a water stream, typically about 4 to 6 wt % of the hydrocarbon feed oil. Intense mixing of the water and hydrocarbon fee oil takes place over a mixing valve and (optionally) a static mixer. The desalter is typically a large liquid-full vessel, and it uses an electric field to separate the hydrocarbon feed oil from the water droplets. It can operate best at temperatures from 120° C. to 150° C., hence it can be conveniently placed somewhere in the middle of the preheat train in a refinery. A good performing desalter can remove about 90 wt % of the salt in a raw mineral crude oil.
The process unit used for the process can be placed remotely at a field location, in a transport vessel, or in a refinery. In one embodiment, the treated feed oil is produced upstream from a refinery or in a refinery.
In one embodiment, the treated feed oil is sent to a downstream fluid catalytic cracking (FCC) unit or to another downstream hydroprocessing unit. FCC is widely used to convert high-boiling, high-molecular weight hydrocarbon fractions of petroleum crude oils to more valuable gasoline, olefinic gases, and other products. Cracking of petroleum hydrocarbons was originally done by thermal cracking, which has been almost completely replaced by catalytic cracking because it produces more gasoline with a higher octane rating. It also produces byproduct gases that are more olefinic, and hence more valuable, than those produced by thermal cracking. The feedstock to a FCC unit is usually that portion of the crude oil that has an initial boiling point of 340° C. or higher at atmospheric pressure and an average molecular weight ranging from about 200 to 600 or higher. This portion of crude oil is often referred to as vacuum gas oil or VGO. The FCC process vaporizes and breaks the long-chain molecules of the high-boiling hydrocarbon liquids into much shorter molecules by contacting the feedstock, at high temperature and moderate pressure, with a fluidized powdered catalyst.
Examples of downstream hydroprocessing units include hydroisomerization reactors, hydrocracking units, hydrotreating units, and hydrofinishing units. The products of petroleum refining must meet tight specifications, for example they can have limits on sulfur, nitrogen, olefins, aromatics, and other contaminants, as well as limits on cold flow properties, octane number, and kinematic viscosity. Hydrotreating removes contaminants from distilled crude oil fractions and intermediate process streams. Hydrocracking converts heavy oil fractions into lighter, more valuable products. Hydrotreating and hydrocracking processes share many common features, so they often are discussed together as “hydroprocessing.” Most hydroprocessing units employ specialized catalysts. As the name implies, they all consume hydrogen. Some chemical reactions that can occur during downstream hydroprocessing can include hydrodesulfurization (HDS), hydrodenitrogenation (HDN), hydrodeoxygenation, the saturation of olefins and aromatics, and hydroisomerization. In one embodiment, the downstream hydroprocessing unit may comprise more than one reactor or perform more than one chemical reaction.
The time for the vigorous mixing is selected to achieve sufficient precipitation of the metal-naphthenate salt, such that when the metal-naphthenate salt is removed, it reduces the initial TAN of the hydrocarbon feed oil by 50 to 100% in the treated feed oil. The time can be from a few seconds to a few hours, such as from five seconds to five hours (18,000 seconds). In one embodiment, the vigorous mixing occurs over a time from 15 seconds to 15,000 seconds.
In one embodiment, the removing step can involve gravity separation. One example of gravity separation is decantation. In one embodiment, the process additionally comprises treating the mixture to accumulate the metal-naphthenate salt in an oil/water interface prior to the removing step. For example, the treatment could be centrifuging the mixture or applying an electrostatic field to the mixture.
In one embodiment, the metal-naphthenate salt is removed by decanting. In another embodiment, the removing can additionally comprise filtering to remove the solids that comprise the metal-naphthenate salt.
The removing of the metal-naphthenate salt greatly reduces the initial TAN by 50 to 100% in the treated feed oil. In one embodiment, the end TAN of the treated feed oil is less than 2 mg KOH/g, such as from 0 to less than 1 mg KOH/g. In one embodiment, the end TAN of the treated feed oil is 0.5 mg KOH/g or less.
During the removing step, a lower aqueous phase can also be separated from the treated feed oil. With efficient separation of the treated feed oil from the aqueous phase, the treated feed oil can comprise less than 1 wt % water, such as from 10 wppm to less than 5000 wppm water. In one embodiment, the process can additionally comprise dehydrating the treated feed oil to reduce the water even further or to meet water specifications.
The transitional term “comprising”, which is synonymous with “including,” “containing,” or “characterized by,” is inclusive or open-ended and does not exclude additional, unrecited elements or method steps. The transitional phrase “consisting of” excludes any element, step, or ingredient not specified in the claim. The transitional phrase “consisting essentially of” limits the scope of a claim to the specified materials or steps “and those that do not materially affect the basic and novel characteristic(s)” of the claimed invention.
For the purposes of this specification and appended claims, unless otherwise indicated, all numbers expressing quantities, percentages or proportions, and other numerical values used in the specification and claims, are to be understood as being modified in all instances by the term “about.” Furthermore, all ranges disclosed herein are inclusive of the endpoints and are independently combinable. Whenever a numerical range with a lower limit and an upper limit are disclosed, any number falling within the range is also specifically disclosed. Unless otherwise specified, all percentages are in weight percent.
Any term, abbreviation or shorthand not defined is understood to have the ordinary meaning used by a person skilled in the art at the time the application is filed. The singular forms “a,” “an,” and “the,” include plural references unless expressly and unequivocally limited to one instance.
All of the publications, patents and patent applications cited in this application are herein incorporated by reference in their entirety to the same extent as if the disclosure of each individual publication, patent application or patent was specifically and individually indicated to be incorporated by reference in its entirety.
This written description uses examples to disclose the invention, including the best mode, and also to enable any person skilled in the art to make and use the invention. Many modifications of the exemplary embodiments of the invention disclosed above will readily occur to those skilled in the art. Accordingly, the invention is to be construed as including all structure and methods that fall within the scope of the appended claims. Unless otherwise specified, the recitation of a genus of elements, materials or other components, from which an individual component or mixture of components can be selected, is intended to include all possible sub-generic combinations of the listed components and mixtures thereof.
The invention illustratively disclosed herein suitably may be practiced in the absence of any element which is not specifically disclosed herein.
A model hydrocarbon feed having an initial TAN of 18 mg KOH/g was prepared by mixing mineral crude oil derived naphthenic acids (obtained from Merichem Company, Houston, Tex.) with toluene.
An aqueous solution of 2 wt % CaCl2 was prepared. The pH of this solution was adjusted to pH=12 by adding a NaOH solution with concentration of 10 wt %. 10 g of the model hydrocarbon feed with TAN=18 was added to 10 g of the 2% CaCl2 solution and the mixed solution was vigorously hand shaken for 1 minute. The Ca2+ to naphthenic acid mole ratio in the mixed solution was 0.56:1, which was close to the stoichiometric ratio (=0.50:1) for calcium naphthenate formation. After the period of shaking, the mixed solution was centrifuged. After centrifuging, a distinct white middle layer was observed at the oil/water interface. A top layer of contacted model hydrocarbon feed was collected by decantation for end TAN analysis and the % TAN reduction was determined. The results of this batch test on the model hydrocarbon feed are shown in Table 1.
The batch test described in Example 2 was repeated on a high acid crude oil. The high acid crude oil was an Albacora crude oil with an initial TAN of 1.77 mg KOH/g. The end TAN was 0.61 mg KOH/g, for a 66% reduction in TAN.
A batch test was conducted to use Ca(OH)2 to treat the model hydrocarbon feed described in Example 1. The results of this batch test are shown in Table 2.
79%
The batch test described in Example 4 was repeated on a high acid crude oil. The high acid crude oil was an Albacora crude oil with an initial TAN of 1.77 mg KOH/g. The results of this batch test are shown in Table 3. The end TAN was 0.03 mg KOH/g, for a 98% reduction in TAN.
98%
Additional tests were conducted to test effectiveness of TAN reduction through naphthenate precipitation for different crudes, and to optimize treatment temperature and mixing conditions.
Merey is a heavy mineral crude oil from Venezuela with API=16 and TAN=1.87. In order to improve mixing, the TAN reduction test was conducted at a higher temperature to reduce the crude oil's viscosity and enhance oil-aqueous phase mixing. Table 4 summarizes the TAN reduction performance.
63%
In a refinery, the crude oil distillation unit is typically fed with a blend of several different crude oils (instead of a neat crude). Therefore, from a practical perspective, it can be more relevant to test TAN reduction for a crude oil blend. Table 5 summarizes the TAN reduction result for a crude oil blend from the Chevron El Segundo refinery (ELS 2CU).
This batch test was run at room temperature. Although a higher temperature would have helped to reduce the oil's viscosity and hence improve oil-aqueous mixing, mixing at higher temperature can also lead to lower solubility of Ca(OH)2 in water. Most alkaline earth metal salts or hydroxides have the property of reverse solubility, i.e. their solubility in water decreases with increasing temperature. Therefore, running at lower temperature can help to maintain a higher Ca concentration in an aqueous phase to react with naphthenic acids in the crude oil.
However, at room temperature, we needed a longer total time for the vigorous mixing to achieve the desired TAN reduction. For this specific sample, we can see that shaking the oil-aqueous mixture for 2 hr. reduced the TAN in the crude oil blend from 3.29 to 0.7, for a 79% TAN reduction.
79%
This example demonstrates that a high degree of TAN reduction can be achieved through a multiple step treatment. In this example, the combining, the vigorously mixing, the precipitating, and the removing steps a) to d) are repeated in series, and the total time for the vigorous mixing was 75 minutes or less. The same blended crude oil as described in Example 7 was used in this batch test. In a first step treatment, the crude oil blend was shaken for 30 min at room temperature. After this step, the TAN was reduced from 3.29 to 1.4.
A second step treatment, at the same conditions, provided further TAN reduction, from 1.4 to 0.7. Overall the TAN of the crude blend was reduced from 3.29 to 0.7, for a total TAN reduction of 79%. The multiple-step treatment was much quicker than the single-step treatment in Example 7. In this example the total time for the vigorous mixing was only 60 minutes. Using a multiple-step treatment, compared to a single step treatment, can reduce the total time for the vigorously mixing step significantly, such as from 25 to 80%.
57%
79%
This application claims the benefit of US Provisional Application No. 62/446909, filed Jan. 17, 2017, herein incorporated in its entirety.
| Number | Date | Country | |
|---|---|---|---|
| 62446909 | Jan 2017 | US |
